1. Field of the Invention
The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations.
2. Description of Related Art
Hydrocarbons obtained from subterranean (e.g., sedimentary) formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.
A wellbore may be formed in a formation. In some embodiments, logging while drilling (LWD), seismic while drilling (SWD), and/or measurement while drilling (MWD) techniques may be used to determine a location of a wellbore while the wellbore is being drilled. Examples of these techniques are disclosed in U.S. Pat. No. 5,899,958 to Dowell et al.; U.S. Pat. No. 6,078,868 to Dubinsky; U.S. Pat. No. 6,084,826 to Leggett, III; U.S. Pat. No. 6,088,294 to Leggett, III et al.; and U.S. Pat. No. 6,427,124 to Dubinsky et al., each of which is incorporated by reference as if fully set forth herein.
In some embodiments, a casing or other pipe system may be placed or formed in a wellbore. U.S. Pat. No. 4,572,299 issued to Van Egmond et al., which is incorporated by reference as if fully set forth herein, describes spooling an electric heater into a well. In some embodiments, components of a piping system may be welded together. Quality of formed wells may be monitored by various techniques. In some embodiments, quality of welds may be inspected by a hybrid electromagnetic acoustic transmission technique known as EMAT. EMAT is described in U.S. Pat. No. 5,652,389 to Schaps et al.; U.S. Pat. No. 5,760,307 to Latimer et al.; U.S. Pat. No. 5,777,229 to Geier et al.; and U.S. Pat. No. 6,155,117 to Stevens et al., each of which is incorporated by reference as if fully set forth herein.
In some embodiments, an expandable tubular may be used in a wellbore. Expandable tubulars are described in U.S. Pat. No. 5,366,012 to Lohbeck, and U.S. Pat. No. 6,354,373 to Vercaemer et al., each of which is incorporated by reference as if fully set forth herein.
Heaters may be placed in wellbores to heat a formation during an in situ process. Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Pat. No. 2,634,961 to Ljungstrom; U.S. Pat. No. 2,732,195 to Ljungstrom; U.S. Pat. No. 2,780,450 to Ljungstrom; U.S. Pat. No. 2,789,805 to Ljungstrom; U.S. Pat. No. 2,923,535 to Ljungstrom; and U.S. Pat. No. 4,886,118 to Van Meurs et al.; each of which is incorporated by reference as if fully set forth herein.
Application of heat to oil shale formations is described in U.S. Pat. No. 2,923,535 to Ljungstrom and U.S. Pat. No. 4,886,118 to Van Meurs et al. Heat may be applied to the oil shale formation to pyrolyze kerogen in the oil shale formation. The heat may also fracture the formation to increase permeability of the formation. The increased permeability may allow formation fluid to travel to a production well where the fluid is removed from the oil shale formation. In some processes disclosed by Ljungstrom, for example, an oxygen containing gaseous medium is introduced to a permeable stratum, preferably while still hot from a preheating step, to initiate combustion.
A heat source may be used to heat a subterranean formation. Electric heaters may be used to heat the subterranean formation by radiation and/or conduction. An electric heater may resistively heat an element. U.S. Pat. No. 2,548,360 to Germain, which is incorporated by reference as if fully set forth herein, describes an electric heating element placed in a viscous oil in a wellbore. The heater element heats and thins the oil to allow the oil to be pumped from the wellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which is incorporated by reference as if fully set forth herein, describes electrically heating tubing of a petroleum well by passing a relatively low voltage current through the tubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electric heating element that is cemented into a well borehole without a casing surrounding the heating element.
U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element that is positioned in a casing. The heating element generates radiant energy that heats the casing. A granular solid fill material may be placed between the casing and the formation. The casing may conductively heat the fill material, which in turn conductively heats the formation.
U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element. The heating element has an electrically conductive core, a surrounding layer of insulating material, and a surrounding metallic sheath. The conductive core may have a relatively low resistance at high temperatures. The insulating material may have electrical resistance, compressive strength, and heat conductivity properties that are relatively high at high temperatures. The insulating layer may inhibit arcing from the core to the metallic sheath. The metallic sheath may have tensile strength and creep resistance properties that are relatively high at high temperatures.
U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electrical heating element having a copper-nickel alloy core.
Combustion of a fuel may be used to heat a formation. Combusting a fuel to heat a formation may be more economical than using electricity to heat a formation. Several different types of heaters may use fuel combustion as a heat source that heats a formation. The combustion may take place in portions of the formation, in a well, and/or near the surface. Previous combustion methods have included using a fireflood. An oxidizer is pumped into the formation. The oxidizer and hydrocarbons in the formation are then ignited to advance a fire front towards a production well. Oxidizer pumped into the formation typically flows through the formation along fracture lines in the formation. Ignition of the oxidizer and hydrocarbons may not result in the fire front flowing uniformly through the formation.
A flameless combustor may be used to combust fuel in a well. U.S. Pat. No. 5,255,742 to Mikus; U.S. Pat. No. 5,404,952 to Vinegar et al.; U.S. Pat. No. 5,862,858 to Wellington et al.; and U.S. Pat. No. 5,899,269 to Wellington et al., which are incorporated by reference as if fully set forth herein, describe flameless combustors. Flameless combustion may be established by preheating a fuel and air mixture to a temperature above an auto-ignition temperature of the mixture. The fuel and air may be mixed in a heating zone to react. A catalytic surface may be provided in the heated zone to lower the auto-ignition temperature of the fuel and air mixture.
In some embodiments, a flameless distributed combustor may include a membrane or membranes that allow for separation of desired components of exhaust gas. Examples of flameless distributed combustors that use membranes are illustrated in U.S. Provisional Application 60/273,354 filed on Mar. 5, 2001; U.S. Patent Application Publication No. 2003-0068260 filed on Mar. 5, 2002; U.S. Provisional Application 60/273,353 filed on Mar. 5, 2001; and U.S. Patent Application Publication No. 2003-0068269 filed on Mar. 5, 2002, each of which is incorporated by reference as if fully set forth herein.
Heat may be supplied to a formation from a surface heater. The surface heater may produce combustion gases that are circulated through wellbores to heat the formation. Alternately, a surface burner may be used to heat a heat transfer fluid that is passed through a wellbore to heat the formation. Examples of fired heaters, or surface burners that may be used to heat a subterranean formation, are illustrated in U.S. Pat. No. 6,056,057 to Vinegar et al. and U.S. Pat. No. 6,079,499 to Mikus et al., which are both incorporated by reference as if fully set forth herein.
Downhole conditions may be monitored during an in situ process. Downhole conditions may be monitored using temperature sensors, pressure sensors, and other instrumentation. A thermowell and temperature logging process, such as that described in U.S. Pat. No. 4,616,705 issued to Stegemeier et al., which is incorporated by reference as if fully set forth herein, may be used to monitor temperature. Sound waves may be used to measure temperature. Using sound waves to measure temperature is described in U.S. Pat. No. 5,624,188 to West; U.S. Pat. No. 5,437,506 to Gray; U.S. Pat. No. 5,349,859 to Kleppe; U.S. Pat. No. 4,848,924 to Nuspl et al.; U.S. Pat. No. 4,762,425 to Shakkottai et al.; and U.S. Pat. No. 3,595,082 to Miller, Jr., which are incorporated by reference as if fully set forth herein.
Coal is often mined and used as a fuel in an electricity generating power plant. Most coal that is used as a fuel to generate electricity is mined. A significant number of coal formations are not suitable for economical mining. For example, mining coal from steeply dipping coal seams, from relatively thin coal seams (e.g., less than about 1 meter thick), and/or from deep coal seams may not be economically feasible. Deep coal seams include coal seams that are at, or extend to, depths of greater than about 3000 feet (about 914 m) below surface level. The energy conversion efficiency of burning coal to generate electricity is relatively low as compared to burning fuels such as natural gas. Also, burning coal to generate electricity often generates significant amounts of carbon dioxide, oxides of sulfur, and oxides of nitrogen that may be released into the atmosphere.
Some hydrocarbon formation may include oxygen containing compounds. Treating a formation that includes oxygen containing compounds may allow for the production of phenolic compounds and phenol. Separation of the phenol from a hydrocarbon mixture may be desirable. Production of phenol from a mixture of xylenols is described in U.S. Pat. No. 2,998,457 issued to Paulsen, et al., which is incorporated by reference as if fully set forth herein.
Synthesis gas may be produced in reactors or in situ in a subterranean formation. Synthesis gas may be produced in a reactor by partially oxidizing methane with oxygen. In situ production of synthesis gas may be economically desirable to avoid the expense of building, operating, and maintaining a surface synthesis gas production facility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated by reference as if fully set forth herein, describes a system for in situ gasification of coal. A subterranean coal seam is burned from a first well towards a production well. Methane, hydrocarbons, H2, CO, and other fluids may be removed from the formation through the production well. The H2 and CO may be separated from the remaining fluid. The H2 and CO may be sent to fuel cells to generate electricity.
U.S. Pat. No. 4,057,293 to Garrett, which is incorporated by reference as if fully set forth herein, discloses a process for producing synthesis gas. A portion of a rubble pile is burned to heat the rubble pile to a temperature that generates liquid and gaseous hydrocarbons by pyrolysis. After pyrolysis, the rubble is further heated, and steam or steam and air are introduced to the rubble pile to generate synthesis gas.
U.S. Pat. No. 5,554,453 to Steinfeld et al., which is incorporated by reference as if fully set forth herein, describes an ex situ coal gasifier that supplies fuel gas to a fuel cell. The fuel cell produces electricity. A catalytic burner is used to burn exhaust gas from the fuel cell with an oxidant gas to generate heat in the gasifier.
Properties of condensed hydrocarbon fluids produced by ex situ retorting of coal are reported in Great Britain Published Patent Application No. GB 2,068,014 A, which is incorporated by reference as if fully set forth herein. The properties of the condensed hydrocarbons may serve as a baseline for comparing the properties of condensed hydrocarbon fluid obtained from in situ processes.
Synthesis gas may be used in a wide variety of processes to make chemical compounds and/or to produce electricity. Synthesis gas may be converted to hydrocarbons using a Fischer-Tropsch process. U.S. Pat. No. 4,096,163 to Chang et al.; U.S. Pat. No. 4,594,468 to Minderhoud; U.S. Pat. No. 6,085,512 to Agee et al.; and U.S. Pat. No. 6,172,124 to Wolflick et al., which are incorporated by reference as if fully set forth herein, describe conversion processes. Synthesis gas may be used to produce methane. Examples of a catalytic methanation process are illustrated in U.S. Pat. No. 3,922,148 to Child; U.S. Pat. No. 4,130,575 to Jorn et al.; and U.S. Pat. No. 4,133,825 to Stroud et al., which are incorporated by reference as if fully set forth herein. Synthesis gas may be used to produce methanol. Examples of processes for production of methanol are described in U.S. Pat. Nos. 4,407,973 to van Dijk et al., U.S. Pat. No. 4,927,857 to McShea, III et al., and U.S. Pat. No. 4,994,093 to Wetzel et al., each of which is incorporated by reference as if fully set forth herein. Synthesis gas may be used to produce engine fuels. Examples of processes for producing engine fuels are described in U.S. Pat. No. 4,076,761 to Chang et al., U.S. Pat. No. 4,138,442 to Chang et al., and U.S. Pat. No. 4,605,680 to Beuther et al., each of which is incorporated by reference as if fully set forth herein.
Carbon dioxide may be produced from combustion of fuel and from many chemical processes. Carbon dioxide may be used for various purposes, such as, but not limited to, a feed stream for a dry ice production facility, supercritical fluid in a low temperature supercritical fluid process, a flooding agent for coal bed demethanation, and a flooding agent for enhanced oil recovery. Although some carbon dioxide is productively used, many tons of carbon dioxide are vented to the atmosphere. In some processes, carbon dioxide may be sequestered in a formation. U.S. Pat. No. 5,566,756 to Chaback et al., which is incorporated by reference as if fully set forth herein, describes carbon dioxide sequestration.
Retorting processes for oil shale may be generally divided into two major types: aboveground (surface) and underground (in situ). Aboveground retorting of oil shale typically involves mining and construction of metal vessels capable of withstanding high temperatures. The quality of oil produced from such retorting may be poor, thereby requiring costly upgrading. Aboveground retorting may also adversely affect environmental and water resources due to mining, transporting, processing, and/or disposing of the retorted material. Many U.S. patents have been issued relating to aboveground retorting of oil shale. Currently available aboveground retorting processes include, for example, direct, indirect, and/or combination heating methods.
In situ retorting typically involves retorting oil shale without removing the oil shale from the ground by mining. “Modified” in situ processes typically require some mining to develop underground retort chambers. An example of a “modified” in situ process includes a method developed by Occidental Petroleum that involves mining approximately 20% of the oil shale in a formation, explosively rubblizing the remainder of the oil shale to fill up the mined out area, and combusting the oil shale by gravity stable combustion in which combustion is initiated from the top of the retort. Other examples of “modified” in situ processes include the “Rubble In Situ Extraction” (“RISE”) method developed by the Lawrence Livermore Laboratory (“LLL”) and radio-frequency methods developed by IIT Research Institute (“IITRI”) and LLL, which involve tunneling and mining drifts to install an array of radio-frequency antennas in an oil shale formation.
Obtaining permeability in an oil shale formation (e.g., between injection and production wells) tends to be difficult because oil shale is often substantially impermeable. Many methods have attempted to link injection and production wells. These methods include: hydraulic fracturing such as methods investigated by Dow Chemical and Laramie Energy Research Center; electrical fracturing (e.g., by methods investigated by Laramie Energy Research Center); acid leaching of limestone cavities (e.g., by methods investigated by Dow Chemical); steam injection into permeable nahcolite zones to dissolve the nahcolite (e.g., by methods investigated by Shell Oil and Equity Oil); fracturing with chemical explosives (e.g., by methods investigated by Talley Energy Systems); fracturing with nuclear explosives (e.g., by methods investigated by Project Bronco); and combinations of these methods. Many of these methods, however, have relatively high operating costs and lack sufficient injection capacity.
An example of an in situ retorting process is illustrated in U.S. Pat. No. 3,241,611 to Dougan, which is incorporated by reference as if fully set forth herein. Dougan discloses a method involving the use of natural gas for conveying kerogen-decomposing heat to the formation. The heated natural gas may be used as a solvent for thermally decomposed kerogen. The heated natural gas exercises a solvent-stripping action with respect to the oil shale by penetrating pores that exist in the shale. The natural gas carrier fluid, accompanied by decomposition product vapors and gases, passes through extraction wells into product recovery lines, and into and through condensers interposed in such lines, where the decomposition vapors condense, leaving the natural gas carrier fluid to flow through a heater and into an injection well drilled into the deposit of oil shale.
Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar) contained in relatively permeable formations (e.g., in tar sands) are found in North America, South America, Africa, and Asia. Tar can be surface-mined and upgraded to lighter hydrocarbons such as crude oil, naphtha, kerosene, and/or gas oil. Surface milling processes may further separate the bitumen from sand. The separated bitumen may be converted to light hydrocarbons using conventional refinery methods. Mining and upgrading tar sand is usually substantially more expensive than producing lighter hydrocarbons from conventional oil reservoirs.
U.S. Pat. No. 5,340,467 to Gregoli et al. and U.S. Pat. No. 5,316,467 to Gregoli et al., which are incorporated by reference as if fully set forth herein, describe adding water and a chemical additive to tar sand to form a slurry. The slurry may be separated into hydrocarbons and water.
U.S. Pat. No. 4,409,090 to Hanson et al., which is incorporated by reference as if fully set forth herein, describes physically separating tar sand into a bitumen-rich concentrate that may have some remaining sand. The bitumen-rich concentrate may be further separated from sand in a fluidized bed.
U.S. Pat. No. 5,985,138 to Humphreys and U.S. Pat. No. 5,968,349 to Duyvesteyn et al., which are incorporated by reference as if fully set forth herein, describe mining tar sand and physically separating bitumen from the tar sand. Further processing of bitumen in treatment facilities may upgrade oil produced from bitumen.
In situ production of hydrocarbons from tar sand may be accomplished by heating and/or injecting a gas into the formation. U.S. Pat. No. 5,211,230 to Ostapovich et al. and U.S. Pat. No. 5,339,897 to Leaute, which are incorporated by reference as if fully set forth herein, describe a horizontal production well located in an oil-bearing reservoir. A vertical conduit may be used to inject an oxidant gas into the reservoir for in situ combustion.
U.S. Pat. No. 2,780,450 to Ljungstrom describes heating bituminous geological formations in situ to convert or crack a liquid tar-like substance into oils and gases.
U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated by reference as if fully set forth herein, describes contacting oil, heat, and hydrogen simultaneously in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.
U.S. Pat. No. 5,046,559 to Glandt and U.S. Pat. No. 5,060,726 to Glandt et al., which are incorporated by reference as if fully set forth herein, describe preheating a portion of a tar sand formation between an injector well and a producer well. Steam may be injected from the injector well into the formation to produce hydrocarbons at the producer well.
Substantial reserves of heavy hydrocarbons are known to exist in formations that have relatively low permeability. For example, billions of barrels of oil reserves are known to exist in diatomaceous formations in California. Several methods have been proposed and/or used for producing heavy hydrocarbons from relatively low permeability formations.
U.S. Pat. No. 5,415,231 to Northrop et al., which is incorporated by reference as if fully set forth herein, describes a method for recovering hydrocarbons (e.g., oil) from a low permeability subterranean reservoir of the type comprised primarily of diatomite. A first slug or volume of a heated fluid (e.g., 60% quality steam) is injected into the reservoir at a pressure greater than the fracturing pressure of the reservoir. The well is then shut in and the reservoir is allowed to soak for a prescribed period (e.g., 10 days or more) to allow the oil to be displaced by the steam into the fractures. The well is then produced until the production rate drops below an economical level. A second slug of steam is then injected and the cycles are repeated.
U.S. Pat. No. 4,530,401 to Hartman et al., which is incorporated by reference as if fully set forth herein, describes a method for the recovery of viscous oil from a subterranean, viscous oil-containing formation by injecting steam into the formation.
U.S. Pat. No. 4,640,352 to Van Meurs et al., which is incorporated by reference as if fully set forth herein, describes a method for recovering hydrocarbons (e.g., heavy hydrocarbons) from a low permeability subterranean reservoir of the type comprised primarily of diatomite.
U.S. Pat. No. 5,339,897 to Leaute describes a method and apparatus for recovering and/or upgrading hydrocarbons utilizing in situ combustion and horizontal wells.
U.S. Pat. No. 5,431,224 to Laali, which is incorporated by reference as if fully set forth herein, describes a method for improving hydrocarbon flow from low permeability tight reservoir rock.
U.S. Pat. No. 5,297,626 Vinegar et al. U.S. Pat. No. and 5,392,854 to Vinegar et al., which are incorporated by reference as if fully set forth herein, describe processes wherein oil containing subterranean formations are heated. The following patents are incorporated herein by reference: U.S. Pat. No. 6,152,987 to Ma et al.; U.S. Pat. No. 5,525,322 to Willms; U.S. Pat. No. 5,861,137 to Edlund; and U.S. Pat. No. 5,229,102 to Minet et al.
As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.
U.S. Pat. No. RE 36,569 to Kuckes, which is incorporated by reference as if fully set forth herein, describes a method for determining distance from a borehole to a nearby, substantially parallel target well for use in guiding the drilling of the borehole. The method includes positioning a magnetic field sensor in the borehole at a known depth and providing a magnetic field source in the target well.
U.S. Pat. No. 5,515,931 to Kuckes and U.S. Pat. No. 5,657,826 to Kuckes, which are incorporated by reference as if fully set forth herein, describe single guide wire systems for use in directional drilling of boreholes. The systems include a guide wire extending generally parallel to the desired path of the borehole.
U.S. Pat. No. 5,725,059 to Kuckes et al., which is incorporated by reference as if fully set forth herein, describes a method and apparatus for steering boreholes for use in creating a subsurface barrier layer. The method includes drilling a first reference borehole, retracting the drill stem while injecting a sealing material into the earth around the borehole, and simultaneously pulling a guide wire into the borehole. The guide wire is used to produce a corresponding magnetic field in the earth around the reference borehole. The vector components of the magnetic field are used to determine the distance and direction from the borehole being drilled to the reference borehole in order to steer the borehole being drilled. U.S. Pat. No. 5,512,830 to Kuckes; U.S. Pat. No. 5,676,212 to Kuckes; U.S. Pat. No. 5,541,517 to Hartmann et al.; U.S. Pat. No. 5,589,775 to Kuckes; U.S. Pat. No. 5,787,997 to Hartmann; and U.S. Pat. No. 5,923,170 to Kuckes, each of which is incorporated by reference as if fully set forth herein, describe methods for measurement of the distance and direction between boreholes using magnetic or electromagnetic fields.
During some in situ process embodiments, cement may be used. In some embodiments, sulfur cement may be utilized. U.S. Pat. No. 4,518,548 to Yarbrough and U.S. Pat. No. 4,428,700 to Lennemann, which are both incorporated by reference as if fully set forth herein, describe sulfur cements. Above about 160° C., molten sulfur changes from a form with eight sulfurs in a ring to an open chain form. When the rings open and if hydrogen sulfide is present, the hydrogen sulfide may terminate the chains, and the viscosity will not increase significantly, but the viscosity will increase. If hydrogen sulfide has been stripped from the molten sulfur, then the short chains may join and form very long molecules. The viscosity may increase dramatically. Molten sulfur may be kept in a range from about 110° C. to about 130° C. to keep the sulfur in the eight chain ring form.